Mobile pressure optimization unit for drilling operations

ABSTRACT

A well drilling method can include transporting a pressure optimization unit to a rig site, the pressure optimization unit including a choke manifold, a control system which automatically controls operation of the choke manifold, and a flowmeter which measures flow of drilling fluid through the choke manifold, and then interconnecting the pressure optimization unit to rig drilling equipment. A pressure optimization unit for use with a well drilling system can include a choke manifold, a control system which automatically controls operation of the choke manifold, and a flowmeter which measures flow of drilling fluid through the choke manifold. The choke manifold, control system and flowmeter may be incorporated into a same conveyance which transports the pressure optimization unit to a rig site.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit under 35 USC §119 of the filing date of International Application Serial No. PCT/US11/036616, filed 16 May 2011. The entire disclosure of this prior application is incorporated herein by this reference.

BACKGROUND

The present disclosure relates generally to equipment utilized and operations performed in conjunction with well drilling operations and, in an embodiment described herein, more particularly provides a mobile pressure optimization unit for use in drilling operations.

Optimized pressure drilling is the art of precisely controlling wellbore pressure during drilling by utilizing a closed annulus and a means for regulating pressure in the annulus. The annulus is typically closed during drilling through use of a rotating control device (RCD, also known as a rotating control head or rotating blowout preventer) which seals about the drill pipe as it rotates. Precise control of wellbore pressure is important for preventing formation damage, preventing loss of drilling fluids, controlling or preventing flow of formation fluids into the wellbore, etc.

It will, therefore, be appreciated that improvements would be beneficial in the art of controlling pressure and flow in drilling operations.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a representative view of a well drilling system and method embodying principles of this disclosure.

FIG. 1A is a representative view of another configuration of the well drilling system.

FIG. 2 is a representative block diagram of a control system which may be used in the well drilling system.

FIG. 3 is a representative side view of a mobile pressure optimization unit, which can embody principles of this disclosure, incorporated into a wheeled vehicle.

FIG. 4 is a representative side view of the mobile pressure optimization unit incorporated into a floating vessel.

FIG. 5 is a representative plan view of the mobile pressure optimization unit.

FIG. 6 is a representative side view of the mobile pressure optimization unit, integrated with a frame of a conveyance used to transport the unit.

DETAILED DESCRIPTION

Representatively and schematically illustrated in FIG. 1 is a well drilling system 10 and associated method which can embody principles of the present disclosure. In the system 10, a wellbore 12 is drilled by rotating a drill bit 14 on an end of a drill string 16. Drilling fluid 18, commonly known as mud, is circulated downward through the drill string 16, out the drill bit 14 and upward through an annulus 20 formed between the drill string and the wellbore 12, in order to cool the drill bit, lubricate the drill string, remove cuttings and provide a measure of wellbore pressure control. A non-return valve 21 (typically a flapper or plunger-type check valve) prevents flow of the drilling fluid 18 upward through the drill string 16 (e.g., when connections are being made in the drill string).

Control of wellbore pressure is very important in optimized pressure drilling (e.g., managed pressure drilling, underbalanced drilling and overbalanced drilling). Preferably, the wellbore pressure is precisely controlled to prevent excessive loss of fluid into the earth formation surrounding the wellbore 12, undesired fracturing of the formation, excessive influx of formation fluids into the wellbore, etc.

In typical managed pressure drilling, it is desired to maintain bottom hole pressure somewhat greater than a pore pressure of the formation being penetrated by the wellbore 12, without exceeding a fracture pressure of the formation. This technique is especially useful in situations where the margin between pore pressure and fracture pressure is relatively small.

In typical underbalanced drilling, it is desired to maintain the bottom hole pressure somewhat less than the pore pressure of the formation, thereby obtaining a controlled influx of fluid from the formation. In typical overbalanced drilling, it is desired to maintain the bottom hole pressure somewhat greater than the pore pressure, thereby preventing (or at least mitigating) influx of fluid from the formation.

Nitrogen or another gas, or another lighter weight fluid, may be added to the drilling fluid 18 for pressure control. This technique is useful, for example, in underbalanced drilling operations.

In the system 10, additional control over the wellbore pressure is obtained by closing off the annulus 20 (e.g., isolating it from communication with the atmosphere and enabling the annulus to be pressurized at or near the surface) using a rotating control device 22 (RCD). The RCD 22 seals about the drill string 16 above a wellhead 24. The drill string 16 extending upwardly through the RCD 22 would connect to, for example, a rotary table (not shown), a standpipe 26, a kelly (not shown), a top drive and/or other conventional drilling equipment.

In one unique feature of the system 10, wellbore pressure is optimized through use of a pressure optimization unit 11. The pressure optimization unit 11 can be conveniently transported to a well site and interconnected with rig drilling equipment, with minimal disruption of a drilling operation, and with reduced time, expense and effort needed for such interconnection.

In the example depicted in FIG. 1, the pressure optimization unit 11 includes a choke manifold 32, a flow diverter 84 and a backpressure pump 86. Each of these is automatically controllable by a control system 90, in a manner more fully described below.

The pressure optimization unit 11 may also include an RCD clamp control 98, an RCD lubricant supply 100 and a fluid analysis system 102. However, note that it is not necessary for the pressure optimization unit 11 to include all of these elements. For example, it is contemplated that the pressure optimization unit 11 will preferably include either the flow diverter 84 or the backpressure pump 86, but not both. Of course, the pressure optimization unit 11 can include additional elements, in keeping with the scope of this disclosure.

The pressure optimization unit 11 can be conveniently interconnected to a rig's drilling system using flexible lines 104 a-g. Rigid lines may also (or alternatively) be used for this purpose, if desired. Preferably, the pressure optimization unit 11 is equipped with hydraulically powered reels 106 (not shown in FIG. 1, see FIG. 5) for storing and deploying the lines 104 a-g.

During drilling, the drilling fluid 18 exits the wellhead 24 via a wing valve 28 in communication with the annulus 20 below the RCD 22. The fluid 18 then flows through mud return lines 30, 73 to the choke manifold 32, which includes redundant chokes 34 (only one of which might be used at a time). Backpressure is applied to the annulus 20 by variably restricting flow of the fluid 18 through the operative choke(s) 34.

The greater the restriction to flow through the choke 34, the greater the backpressure applied to the annulus 20. Thus, downhole pressure (e.g., pressure at the bottom of the wellbore 12, pressure at a downhole casing shoe, pressure at a particular formation or zone, etc.) can be conveniently regulated by varying the backpressure applied to the annulus 20. A hydraulics model can be used, as described more fully below, to determine a pressure applied to the annulus 20 at or near the surface which will result in a desired downhole pressure, so that an operator (or an automated control system) can readily determine how to regulate the pressure applied to the annulus at or near the surface (which can be conveniently measured) in order to obtain the desired downhole pressure.

Pressure applied to the annulus 20 can be measured at or near the surface via a variety of pressure sensors 36, 38, 40, each of which is in communication with the annulus. Pressure sensor 36 senses pressure below the RCD 22, but above a blowout preventer (BOP) stack 42. Pressure sensor 38 senses pressure in the wellhead below the BOP stack 42. Pressure sensor 40 senses pressure in the mud return lines 30, 73 upstream of the choke manifold 32.

Another pressure sensor 44 senses pressure in the standpipe 26. Yet another pressure sensor 46 senses pressure downstream of the choke manifold 32, but upstream of a separator 48, shaker 50 and mud pit 52. Additional sensors include temperature sensors 54, 56, Coriolis flowmeter 58, and flowmeters 62, 64, 66, 88.

Not all of these sensors are necessary. For example, the system 10 could include only two of the three flowmeters 62, 64, 66. However, input from all available sensors is useful to the hydraulics model in determining what the pressure applied to the annulus 20 should be during the drilling operation.

Other sensor types may be used, if desired. For example, it is not necessary for the flowmeter 58 to be a Coriolis flowmeter, since a turbine flowmeter, acoustic flowmeter, or another type of flowmeter could be used instead.

In addition, the drill string 16 may include its own sensors 60, for example, to directly measure downhole pressure. Such sensors 60 may be of the type known to those skilled in the art as pressure while drilling (PWD), measurement while drilling (MWD) and/or logging while drilling (LWD). These drill string sensor systems generally provide at least pressure measurement, and may also provide temperature measurement, detection of drill string characteristics (such as vibration, weight on bit, stick-slip, etc.), formation characteristics (such as resistivity, density, etc.) and/or other measurements. Various forms of wired or wireless telemetry (acoustic, pressure pulse, electromagnetic, etc.) may be used to transmit the downhole sensor measurements to the surface.

Additional sensors could be included in the system 10, if desired. For example, another flowmeter 67 could be used to measure the rate of flow of the fluid 18 exiting the wellhead 24, another Coriolis flowmeter (not shown) could be interconnected directly upstream or downstream of a rig mud pump 68, etc.

Fewer sensors could be included in the system 10, if desired. For example, the output of the rig mud pump 68 could be determined by counting pump strokes, instead of by using the flowmeter 62 or any other flowmeter(s).

Note that the separator 48 could be a 3 or 4 phase separator, or a mud gas separator (sometimes referred to as a “poor boy degasser”). However, the separator 48 is not necessarily used in the system 10.

The drilling fluid 18 is pumped through the standpipe 26 and into the interior of the drill string 16 by the rig mud pump 68. The pump 68 receives the fluid 18 from the mud pit 52 and flows it via a standpipe manifold 70 to the standpipe 26. The fluid 18 then circulates downward through the drill string 16, upward through the annulus 20, through the mud return lines 30, 73, through the choke manifold 32, and then via the separator 48 and shaker 50 to the mud pit 52 for conditioning and recirculation.

Note that, in the system 10 as so far described above, the choke 34 cannot be used to control backpressure applied to the annulus 20 for control of the downhole pressure, unless the fluid 18 is flowing through the choke. In conventional overbalanced drilling operations, a lack of fluid 18 flow will occur, for example, whenever a connection is made in the drill string 16 (e.g., to add another length of drill pipe to the drill string as the wellbore 12 is drilled deeper), and the lack of circulation will require that downhole pressure be regulated solely by the density of the fluid 18.

In the system 10, however, flow of the fluid 18 through the choke 34 can be maintained, even though the fluid does not circulate through the drill string 16 and annulus 20, while a connection is being made in the drill string, and/or while the drill string is being tripped into or out of the wellbore 12. Specifically, a flow diverter 84 may be used to divert flow from the rig mud pump 68 to the mud return line 30, or a backpressure pump 86 may be used to supply flow through the choke manifold 32, and thereby enable precise control over pressure in the wellbore 12. Thus, pressure can still be applied to the annulus 20 by restricting flow of the fluid 18 through the choke 34, even while the fluid does not circulate through the drill string 16.

The fluid 18 can be flowed from the rig mud pump 68 to the choke manifold 32 via a bypass line 72, 75 when fluid 18 does not flow through the drill string 16. Thus, the fluid 18 can bypass the standpipe 26, drill string 16 and annulus 20, and can flow directly from the pump 68 to the mud return line 30, which remains in communication with the annulus 20. Restriction of this flow by the choke 34 will thereby cause pressure to be applied to the annulus 20 (for example, in typical managed pressure drilling).

Alternatively, the fluid 18 can be flowed from the backpressure pump 86 to the annulus 20 and, since the annulus is connected to the choke manifold 32 via the return line 73, 30, this will supply flow through the choke 34, so that wellbore pressure can be controlled by variably restricting the flow through the choke.

As depicted in FIG. 1, both of the bypass line 75 and the mud return line 30 are in communication with the annulus 20 via a single line 73. However, the bypass line 75 and the mud return line 30 could instead be separately connected to the wellhead 24, for example, using an additional wing valve (e.g., below the RCD 22), in which case each of the lines 30, 75 would be directly in communication with the annulus 20.

Although this might require some additional piping at the rig site, the effect on the annulus pressure would be similar to connecting the bypass line 75 and the mud return line 30 to the common line 73. Thus, it should be appreciated that various different configurations of the components of the system 10 may be used, without departing from the principles of this disclosure.

Flow of the fluid 18 through the bypass line 72, 75 is regulated by a choke or other type of flow control device 74. Line 72 is upstream of the bypass flow control device 74, and line 75 is downstream of the bypass flow control device.

Flow of the fluid 18 through the standpipe 26 is substantially controlled by a valve or other type of flow control device 76. Note that the flow control devices 74, 76 are independently controllable, which provides substantial benefits to the system 10, as described more fully below.

Since the rate of flow of the fluid 18 through each of the standpipe 26 and bypass line 72 is useful in determining how bottom hole pressure is affected by these flows, the flowmeters 64, 66 are depicted in FIG. 1 as being interconnected in these lines. However, the rate of flow through the standpipe 26 could be determined even if only the flowmeters 62, 64 were used, and the rate of flow through the bypass line 72 could be determined even if only the flowmeters 62, 66 were used. Thus, it should be understood that it is not necessary for the system 10 to include all of the sensors depicted in FIG. 1 and described herein, and the system could instead include additional sensors, different combinations and/or types of sensors, etc.

In another beneficial feature of the system 10, a bypass flow control device 78 and flow restrictor 80 may be used for filling the standpipe 26 and drill string 16 after a connection is made in the drill string, and for equalizing pressure between the standpipe and mud return lines 30, 73 prior to opening the flow control device 76. Otherwise, sudden opening of the flow control device 76 prior to the standpipe line 26 and drill string 16 being filled and pressurized with the fluid 18 could cause an undesirable pressure transient in the annulus 20 (e.g., due to flow to the choke manifold 32 temporarily being lost while the standpipe and drill string fill with fluid, etc.).

By opening the standpipe bypass flow control device 78 after a connection is made, the fluid 18 is permitted to fill the standpipe 26 and drill string 16 while a substantial majority of the fluid continues to flow through the bypass line 72, thereby enabling continued controlled application of pressure to the annulus 20. After the pressure in the standpipe 26 has equalized with the pressure in the mud return lines 30, 73 and bypass line 75, the flow control device 76 can be opened, and then the flow control device 74 can be closed to slowly divert a greater proportion of the fluid 18 from the bypass line 72 to the standpipe 26.

Before a connection is made in the drill string 16, a similar process can be performed, except in reverse, to gradually divert flow of the fluid 18 from the standpipe 26 to the bypass line 72 in preparation for adding more drill pipe to the drill string 16. That is, the flow control device 74 can be gradually opened to slowly divert a greater proportion of the fluid 18 from the standpipe 26 to the bypass line 72, and then the flow control device 76 can be closed.

Note that the flow control device 78 and flow restrictor 80 could be integrated into a single element (e.g., a flow control device having a flow restriction therein), if desired. The flow control device 76 can be part of a flow diversion manifold 81 interconnected between the rig mud pump 68 and the rig standpipe manifold 70.

The RCD clamp control 98 is used to remotely operate a clamp (not visible in FIG. 1) of the RCD 22. The clamp is for permitting access to a seal and a bearing assembly of the RCD 22. Examples of electrical and hydraulic remote control of RCD clamps are described in International Application No. PCT/US11/28384, filed 14 Mar. 2011, and in International Application No. PCT/US10/57540, filed 20 Nov. 2010. If a hydraulically operated RCD clamp is used, hydraulic pressure may be supplied to the RCD clamp control 98 from a conveyance (e.g., vehicle, vessel, etc.) which transports the pressure optimization unit 11 to the rig site.

The fluid analysis system 102 is used to determine properties of the fluid 18 which flows from the annulus 20 to the pressure optimization unit 11. The fluid analysis system 102 may include, for example, a gas analyzer which extracts gas from the fluid 18 and determines its composition, a gas spectrometer, a densitometer, a flowmeter, etc. The gas analyzer may be similar to an EAGLE™ gas extraction system and a DQ1000™ mass spectrometer marketed by Halliburton Energy Services, Inc.

The fluid analysis system 102 may include a real time rheology analyzer, which continuously monitors rheological properties of the fluid 18 and transmits this data to the hydraulics model 92. A suitable rheology analyzer for use in the fluid analysis system 102 is described in U.S. Application No. 61/377164, filed 26 Aug. 2010.

Referring additionally now to FIG. 1A, a somewhat different configuration of the system 10 is representatively illustrated. In this configuration, the bypass line 75 is connected to a third choke 82. The bypass line 75 remains connected to the return line 30 also, but the choke 82 provides for convenient regulation of the amount of fluid 18 discharged from the flow diverter 84.

Thus, when resistance to flow through the choke 82 is increased, more of the fluid 18 flows to the mud return line 30. When resistance to flow through the choke 82 is decreased, more of the fluid 18 flows to a downstream side of the choke manifold 32 (and not through the chokes 34).

A pressure and flow control system 90 which may be used in conjunction with the system 10 and associated method of FIGS. 1 & 1A is representatively illustrated in

FIG. 2. The control system 90 is preferably fully automated, although some human intervention may be used, for example, to safeguard against improper operation, initiate certain routines, update parameters, etc.

The control system 90 includes a hydraulics model 92, a data acquisition and control interface 94 and a controller 96 (such as a programmable logic controller or PLC, a suitably programmed computer, etc.). Although these elements 92, 94, 96 are depicted separately in FIG. 2, any or all of them could be combined into a single element, or the functions of the elements could be separated into additional elements, other additional elements and/or functions could be provided, etc.

The hydraulics model 92 is used in the control system 90 to determine the desired annulus pressure at or near the surface to achieve the desired downhole pressure. Data such as well geometry, fluid properties and offset well information (such as geothermal gradient and pore pressure gradient, etc.) are utilized by the hydraulics model 92 in making this determination, as well as real-time sensor data acquired by the data acquisition and control interface 94.

Thus, there is a continual two-way transfer of data and information between the hydraulics model 92 and the data acquisition and control interface 94. It is important to appreciate that the data acquisition and control interface 94 operates to maintain a substantially continuous flow of real-time data from the sensors 44, 54, 66, 62, 64, 60, 58, 46, 36, 38, 40, 56, 67, 88 and fluid analysis system 102 to the hydraulics model 92, so that the hydraulics model has the information it needs to adapt to changing circumstances and to update the desired annulus pressure. The hydraulics model 92 operates to supply the data acquisition and control interface 94 substantially continuously with a value for the desired annulus 20 pressure.

A suitable hydraulics model for use as the hydraulics model 92 in the control system 90 is REAL TIME HYDRAULICS™ provided by Halliburton Energy Services, Inc. of Houston, Tex. USA. Another suitable hydraulics model is provided under the trade name IRIS™, and yet another is available from SINTEF of Trondheim, Norway. Any suitable hydraulics model may be used in the control system 90 in keeping with the principles of this disclosure.

A suitable data acquisition and control interface for use as the data acquisition and control interface 94 in the control system 90 are SENTRY198 and INSITE™ provided by Halliburton Energy Services, Inc. Any suitable data acquisition and control interface may be used in the control system 90 in keeping with the principles of this disclosure.

The controller 96 operates to maintain a desired setpoint annulus pressure, in part by controlling operation of the mud return choke 34. When an updated desired annulus pressure is transmitted from the data acquisition and control interface 94 to the controller 96, the controller uses the desired annulus pressure as a setpoint and controls operation of the choke 34 in a manner (e.g., increasing or decreasing flow resistance through the choke as needed) to maintain the setpoint pressure in the annulus 20. The choke 34 can be closed more to increase flow resistance, or opened more to decrease flow resistance.

Maintenance of the setpoint pressure is accomplished by comparing the setpoint pressure to a measured annulus pressure (such as the pressure sensed by any of the sensors 36, 38, 40), and decreasing flow resistance through the choke 34 if the measured pressure is greater than the setpoint pressure, and increasing flow resistance through the choke if the measured pressure is less than the setpoint pressure. Of course, if the setpoint and measured pressures are the same, then no adjustment of the choke 34 is required. This process is preferably automated, so that no human intervention is required, although human intervention may be used, if desired.

The controller 96 may also be used to control operation of the standpipe flow control devices 76, 78 and the bypass flow control device 74. The controller 96 can, thus, be used to automate the processes of diverting flow of the fluid 18 from the standpipe 26 to the bypass line 72 prior to making a connection in the drill string 16, then diverting flow from the bypass line to the standpipe after the connection is made, and then resuming normal circulation of the fluid 18 for drilling. Again, no human intervention may be required in these automated processes, although human intervention may be used if desired, for example, to initiate each process in turn, to manually operate a component of the system, etc.

The control system 90 also preferably includes a predictive device 148 and a data validator 150. The predictive device 148 preferably comprises one or more neural network models for predicting various well parameters. These parameters could include outputs of any of the sensors 36, 38, 40, 44, 46, 54, 56, 58, 60, 62, 64, 66, 67, 88, 102, the annulus pressure setpoint output from the hydraulics model 92, positions of flow control devices 34, 74, 76, 78, drilling fluid 18 density, etc. Any well parameter, and any combination of well parameters, may be predicted by the predictive device 148.

The predictive device 148 is preferably “trained” by inputting present and past actual values for the parameters to the predictive device. Terms or “weights” in the predictive device 148 may be adjusted based on derivatives of output of the predictive device with respect to the terms.

The predictive device 148 may be trained by inputting to the predictive device data obtained during drilling, while making connections in the drill string 16, and/or during other stages of an overall drilling operation. The predictive device 148 may be trained by inputting to the predictive device data obtained while drilling at least one prior wellbore.

The training may include inputting to the predictive device 148 data indicative of past errors in predictions produced by the predictive device. The predictive device 148 may be trained by inputting data generated by a computer simulation of the well drilling system 10 (including the drilling rig, the well, equipment utilized, etc.).

Once trained, the predictive device 148 can accurately predict or estimate what value one or more parameters should have in the present and/or future. The predicted parameter values can be supplied to the data validator 150 for use in its data validation processes.

The predictive device 148 does not necessarily comprise one or more neural network models. Other types of predictive devices which may be used include an artificial intelligence device, an adaptive model, a nonlinear function which generalizes for real systems, a genetic algorithm, a linear system model, and/or a nonlinear system model, combinations of these, etc.

The predictive device 148 may perform a regression analysis, perform regression on a nonlinear function and may utilize granular computing. An output of a first principle model may be input to the predictive device 148 and/or a first principle model may be included in the predictive device.

The predictive device 148 receives the actual parameter values from the data validator 150, which can include one or more digital programmable processors, memory, etc. The data validator 150 uses various pre-programmed algorithms to determine whether sensor measurements, flow control device positions, etc., received from the data acquisition & control interface 94 are valid.

For example, if a received actual parameter value is outside of an acceptable range, unavailable (e.g., due to a non-functioning sensor) or differs by more than a predetermined maximum amount from a predicted value for that parameter (e.g., due to a malfunctioning sensor), then the data validator 150 may flag that actual parameter value as being “invalid.” Invalid parameter values may not be used for training the predictive device 148, or for determining the desired annulus pressure setpoint by the hydraulics model 92. Valid parameter values would be used for training the predictive device 148, for updating the hydraulics model 92, for recording to the data acquisition & control interface 94 database and, in the case of the desired annulus pressure setpoint, transmitted to the controller 96 for controlling operation of the flow control devices 34, 74, 76, 78.

The desired annulus pressure setpoint may be communicated from the hydraulics model 92 to each of the data acquisition & control interface 94, the predictive device 148 and the controller 96. The desired annulus pressure setpoint is communicated from the hydraulics model 92 to the data acquisition & control interface 94 for recording in its database, and for relaying to the data validator 150 with the other actual parameter values.

The desired annulus pressure setpoint is communicated from the hydraulics model 92 to the predictive device 148 for use in predicting future annulus pressure setpoints. However, the predictive device 148 could receive the desired annulus pressure setpoint (along with the other actual parameter values) from the data validator 150 in other examples.

The desired annulus pressure setpoint is communicated from the hydraulics model 92 to the controller 96 for use in case the data acquisition & control interface 94 or data validator 150 malfunctions, or output from these other devices is otherwise unavailable. In that circumstance, the controller 96 could continue to control operation of the various flow control devices 34, 74, 76, 78 to maintain/achieve the desired pressure in the annulus 20 near the surface.

The predictive device 148 is trained in real time, and is capable of predicting current values of one or more sensor measurements based on the outputs of at least some of the other sensors. Thus, if a sensor output becomes unavailable, the predictive device 148 can supply the missing sensor measurement values to the data validator 150, at least temporarily, until the sensor output again becomes available.

If, for example, during the drill string connection process described above, one of the flowmeters 62, 64, 66 malfunctions, or its output is otherwise unavailable or invalid, then the data validator 150 can substitute the predicted flowmeter output for the actual (or nonexistent) flowmeter output. It is contemplated that, in actual practice, only one or two of the flowmeters 62, 64, 66 may be used. Thus, if the data validator 150 ceases to receive valid output from one of those flowmeters, determination of the proportions of fluid 18 flowing through the standpipe 26 and bypass line 72 could not be readily accomplished, if not for the predicted parameter values output by the predictive device 148. It will be appreciated that measurements of the proportions of fluid 18 flowing through the standpipe 26 and bypass line 72 are very useful, for example, in calculating equivalent circulating density and/or friction pressure by the hydraulics model 92 during the drill string connection process.

Validated parameter values are communicated from the data validator 150 to the hydraulics model 92 and to the controller 96. The hydraulics model 92 utilizes the validated parameter values, and possibly other data streams, to compute the pressure currently present downhole at the point of interest (e.g., at the bottom of the wellbore 12, at a problematic zone, at a casing shoe, etc.), and the desired pressure in the annulus 20 near the surface needed to achieve a desired downhole pressure.

The data validator 150 is programmed to examine the individual parameter values received from the data acquisition & control interface 94 and determine if each falls into a predetermined range of expected values. If the data validator 150 detects that one or more parameter values it received from the data acquisition & control interface 94 is invalid, it may send a signal to the predictive device 148 to stop training the neural network model for the faulty sensor, and to stop training the other models which rely upon parameter values from the faulty sensor to train.

Although the predictive device 148 may stop training one or more neural network models when a sensor fails, it can continue to generate predictions for output of the faulty sensor or sensors based on other, still functioning sensor inputs to the predictive device. Upon identification of a faulty sensor, the data validator 150 can substitute the predicted sensor parameter values from the predictive device 148 to the controller 96 and the hydraulics model 92. Additionally, when the data validator 150 determines that a sensor is malfunctioning or its output is unavailable, the data validator can generate an alarm and/or post a warning, identifying the malfunctioning sensor, so that an operator can take corrective action.

The predictive device 148 is preferably also able to train a neural network model representing the output of the hydraulics model 92. A predicted value for the desired annulus pressure setpoint is communicated to the data validator 150. If the hydraulics model 92 has difficulties in generating proper values or is unavailable, the data validator 150 can substitute the predicted desired annulus pressure setpoint to the controller 96.

Referring additionally now to FIG. 3, the pressure optimization unit 11 is representatively illustrated as being incorporated into a conveyance 110. As depicted in FIG. 3, the conveyance 110 comprises a wheeled vehicle 108 on which the pressure optimization unit 11 is transported, but in other examples the conveyance is not necessarily a wheeled vehicle.

The vehicle 108 illustrated in FIG. 3 is a tractor-trailer, with the pressure optimization unit 11 being incorporated into the trailer portion of the vehicle. In other examples, the vehicle 108 could be a bobtail truck (i.e., without a trailer being towed behind the truck) or another type of wheeled vehicle.

Preferably, the pressure optimization unit 11 is incorporated into the conveyance 110, so that it is part of the conveyance, and is not a separately transportable element. However, in other examples the pressure optimization unit 11 could be separately transported (such as, on a flat bed trailer, etc.).

Referring additionally now to FIG. 4, another configuration of the conveyance 110 is representatively illustrated. In this configuration, the pressure optimization unit 11 is incorporated into a floating vessel 112 (such as a barge, a ship, a floating production, storage and offloading (FPSO) vessel, etc.).

Again, the pressure optimization unit 11 is preferably incorporated into the conveyance 110, so that it is part of the conveyance, and is not an element separately transportable from the vessel 112. However, in other examples the pressure optimization unit 11 could be separately transported (such as, on a work boat, etc.).

Referring additionally now to FIG. 5, a plan view of one configuration of the pressure optimization unit 11 is representatively illustrated. In this configuration, the pressure optimization unit 11 includes the choke manifold 32, the Coriolis flowmeter 58, the flow diverter 84, the control system 90, the fluid analysis system 102 and the reels 106, along with a command center 114 for human interaction with the control system, etc. The command center 114 can include workstations 116 for human-machine interaction, and communication equipment 118 for, e.g., telephone, internet, wireless, satellite and/or internet communication with remote locations.

The fluid analysis system 102 in this example includes both a gas analysis system 120 and a rheology measurement system 122. The gas analysis system 120 may be similar to the EAGLE™ system marketed by Halliburton Energy Services, Inc., and the rheology measurement system 122 may be similar to that described in U.S. Application No. 61/377164. Rheological properties measured by the system 122 can include density, oil/water ratio, specific gravity, chloride amount, electric stability, shear stress, gel strength, viscosity and/or yield point.

Pipe racks 124 may be provided for storing rigid lines. Electrical power, as well as hydraulic and pneumatic pressure, may be supplied to the pressure optimization unit 11 via lines 126 from the vehicle 108 or vessel 112.

Referring additionally now to FIG. 6, one manner in which the pressure optimization unit 11 can be integrated into the conveyance 110 is representatively illustrated. As depicted in FIG. 6, the choke 34 is rigidly attached to a frame 128 of the vehicle 108 or vessel 112. Although only the one choke 34 is shown in FIG. 6, it will be appreciated that any or all of the elements of the pressure optimization unit 11 can be integrated into the vehicle 108 or vessel 112 in keeping with the scope of this disclosure.

By rigidly attaching the choke 34 and/or other elements of the pressure optimization unit 11 to the frame 128 of the vehicle 108 or vessel 112, the pressure optimization unit is incorporated into, and becomes a part of, the conveyance 110. However, in other examples, the pressure optimization unit 11 may not be incorporated into the conveyance 110 (such as, if the pressure optimization unit is transported to the rig site on a flat bed trailer or on a work boat, etc.).

In practice, the pressure optimization unit 11 is preferably transported to the rig site as part of the conveyance 110. Without offloading the pressure optimization unit 11 from the vehicle 108 or vessel 112, the pressure optimization unit is interconnected to the various items of drilling equipment using the lines 104 a-g, and is operational (ready for use in a drilling operation) in a relatively short period of time. In this manner, incorporation of the pressure optimization unit 11 into the drilling operation is convenient, efficient and economical, thereby saving time, money and manpower.

Of course, if the pressure optimization unit 11 is transported to the rig site on a flat bed trailer or a work boat, the pressure optimization unit may be offloaded at the rig site. In these situations, the process of interconnecting the pressure optimization unit 11 to the rig's drilling equipment via the lines 104 a-g will still be relatively convenient, efficient and economical.

Although only the wheeled vehicle 108 and floating vessel 112 are illustrated in the drawings, any type of conveyance may be used to transport the pressure optimization unit 11 to and from the rig site. Trains and aircraft (e.g., a hovercraft) are additional examples of suitable conveyances whereby the pressure optimization unit 11 can be made mobile.

It may now be fully appreciated that the above disclosure provides significant advances to the art of well drilling equipment construction. The pressure optimization unit 11 described above can be conveniently transported to a rig site, and can be interconnected to rig drilling equipment in a convenient, efficient and economical manner.

The above disclosure describes a well drilling method. The method can include transporting a pressure optimization unit 11 to a rig site, the pressure optimization unit 11 including a choke manifold 32, a control system 90 which automatically controls operation of the choke manifold 32, and a flowmeter 58 which measures flow of drilling fluid 18 through the choke manifold 32, and then interconnecting the pressure optimization unit 11 to rig drilling equipment (e.g., the wellhead 24, standpipe 26, separator 48, shaker 50, mud pit 52, etc.).

The method can also include integrating the pressure optimization unit 11 into a conveyance 110. The conveyance 110 may comprise a wheeled vehicle 108 or a floating vessel 112.

The integrating step may include rigidly attaching the pressure optimization unit 11 to a frame 128 of the conveyance 110. The interconnecting step may include interconnecting the pressure optimization unit 11 to the rig drilling equipment, without prior offloading of the pressure optimization unit 11 from the conveyance 110.

The pressure optimization unit 11 may include a flow diverter 84 which diverts flow of the drilling fluid 18 from a standpipe 26 to the choke manifold 32, a backpressure pump 86 which pressurizes a well annulus 20, a fluid analysis system 102 which comprises a gas analysis system 120 and/or a rheology measurement system 122, a rotating control device clamp control 98 and/or a rotating control device lubricant supply 100.

Also described above is a pressure optimization unit 11 for use with a well drilling system 10. The pressure optimization unit 11 can include a choke manifold 32, a control system 90 which automatically controls operation of the choke manifold 32, and a flowmeter 58 which measures flow of drilling fluid 18 through the choke manifold 32. The choke manifold 32, control system 90 and flowmeter 58 can each be incorporated into a same conveyance 110 which transports the pressure optimization unit 11 to a rig site.

The pressure optimization unit 11 may also include a powered reel 106 which stores line 104 a-g that connects the pressure optimization unit 11 to rig drilling equipment (e.g., the wellhead 24, standpipe 26, separator 48, shaker 50, mud pit 52, etc.).

The pressure optimization unit 11 can be interconnected to rig drilling equipment concurrently with the pressure optimization unit 11 being incorporated into the conveyance 110.

It is to be understood that the various embodiments of the present disclosure described herein may be utilized in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without departing from the principles of this disclosure. The embodiments are described merely as examples of useful applications of the principles of the disclosure, which is not limited to any specific details of these embodiments.

Of course, a person skilled in the art would, upon a careful consideration of the above description of representative embodiments of the disclosure, readily appreciate that many modifications, additions, substitutions, deletions, and other changes may be made to the specific embodiments, and such changes are contemplated by the principles of this disclosure. Accordingly, the foregoing detailed description is to be clearly understood as being given by way of illustration and example only, the spirit and scope of the invention being limited solely by the appended claims and their equivalents. 

1-6. (canceled)
 7. A well drilling method, comprising: transporting a pressure optimization unit to a rig site, the pressure optimization unit including a choke manifold, a control system which automatically controls operation of the choke manifold, a flowmeter which measures flow of drilling fluid through the choke manifold, and a flow diverter which diverts flow of the drilling fluid from a standpipe to the choke manifold; and then interconnecting the pressure optimization unit to rig drilling equipment.
 8. A well drilling method, comprising: transporting a pressure optimization unit to a rig site, the pressure optimization unit including a choke manifold, a control system which automatically controls operation of the choke manifold, a flowmeter which measures flow of drilling fluid through the choke manifold, and a backpressure pump which pressurizes a well annulus; and then interconnecting the pressure optimization unit to rig drilling equipment.
 9. A well drilling method, comprising: transporting a pressure optimization unit to a rig site, the pressure optimization unit including a choke manifold, a control system which automatically controls operation of the choke manifold, a flowmeter which measures flow of drilling fluid through the choke manifold, and a fluid analysis system which comprises a gas analysis system; and then interconnecting the pressure optimization unit to rig drilling equipment.
 10. A well drilling method, comprising: transporting a pressure optimization unit to a rig site, the pressure optimization unit including a choke manifold, a control system which automatically controls operation of the choke manifold, a flowmeter which measures flow of drilling fluid through the choke manifold, and a fluid analysis system which comprises a rheology measurement system; and then interconnecting the pressure optimization unit to rig drilling equipment.
 11. A well drilling method, comprising: transporting a pressure optimization unit to a rig site, the pressure optimization unit including a choke manifold, a control system which automatically controls operation of the choke manifold, a flowmeter which measures flow of drilling fluid through the choke manifold, and a rotating control device clamp control; and then interconnecting the pressure optimization unit to rig drilling equipment.
 12. A well drilling method, comprising: transporting a pressure optimization unit to a rig site, the pressure optimization unit including a choke manifold, a control system which automatically controls operation of the choke manifold, a flowmeter which measures flow of drilling fluid through the choke manifold, and a rotating control device lubricant supply; and then interconnecting the pressure optimization unit to rig drilling equipment. 13-24. (canceled) 